1. Field of the Invention
The present invention relates to rotary, earth boring drag bits for drilling subterranean formations, as well as to the operation of such bits. More specifically, the present invention relates to modifying the designs of bits to include bearing elements for effectively reducing the exposure of cutting elements, or cutters, on the crowns of the bits by a readily predictable amount, as well as for optimizing performance of bits in the context of controlling cutter loading or depth-of-cut.
2. State of the Art
Bits that carry polycrystalline diamond compact (PDC) cutting elements, or cutters, have proven very effective in achieving high rates of penetration (ROP) in drilling subterranean formations exhibiting low to medium compressive strengths. A PDC cutter typically includes a disc-shaped diamond “table” formed on and bonded under high-pressure and high-temperature conditions to a supporting substrate, which may be formed from cemented tungsten carbide (WC), although other cutter configurations and substrate materials are known in the art. Recent improvements in the design of hydraulic flow regimes about the face of bits, cutter design, and drilling fluid formulation have reduced prior, notable tendencies of such bits to “ball” by increasing the volume of formation material that may be cut before exceeding the ability of the bit and its associated drilling fluid flow to clear the formation cuttings from the face of the bit.
The body of a rotary, earth boring drag bit may be fabricated by machining a mold cavity in a block of graphite or another material and introducing inserts and cutter displacements into the machined cavities of the mold. The surfaces of the mold cavity define regions on the surface of the drill bit, while the cutter displacements and other inserts may define recesses on the face of the bit body and internal cavities within the bit body. Once any inserts and displacements have been positioned within the mold cavity, a particulate material, such as tungsten carbide, may be introduced into the cavity of the mold. Thereafter, an infiltrant, or binder, material may be introduced into the cavity to secure the particles to one another. The cutter displacements and other inserts may be removed from the bit body following the infiltration process, after which other elements, such as the cutters and hydraulic nozzles, may be assembled with and secured to the bit body.
The relationship of torque-on-bit (TOB) to weight-on-bit (WOB) may be employed as an indicator of aggressivity for cutters, with the TOB-to-WOB ratio corresponding to the aggressiveness with which a cutter is exposed or oriented relative to the crown of a bit or the cone of the crown. When cutters are placed in cavities that have been formed with standard cutter displacements, they may be exposed an aggressive enough distance that a phenomenon that has been referred to in the art as “overloading” may occur, even when a low WOB is applied to the drill string to which the bit is mounted. The occurrence of this phenomenon is more likely with more aggressive exposure or orientation of the cutters. Overloading is particularly significant in low compressive strength formations where a relatively great depth-of-cut (DOC) may be achieved at an extremely low WOB. Overloading may also be caused or exacerbated by drill string bounce, in which the elasticity of the drill string causes erratic, or inconsistent, application of WOB to the drill bit. Moreover, when bits with cutters that are carried by cavities are operated at excessively high DOC, more formation cuttings may be generated than can be consistently cleared from the bit face and directed back up the borehole annulus via junk slots on the face of the bit, which may lead to bit balling.
Another problem that may be caused when cutters located on the crown of a rotary, earth boring drill bit are overexposed may occur while drilling from a zone or stratum of higher formation compressive strength to a “softer” zone of lower compressive strength. As the bit drills from the harder formation into the softer formation without changing the applied WOB, or before a directional driller can change the WOB, the penetration of the PDC cutters and, thus, the resulting torque-on-bit (TOB) increases almost instantaneously and by a substantial magnitude. The abruptly higher torque may, in turn, cause damage to the cutters and/or the bit body. In directional drilling, such a change causes the tool face orientation (TFO) of the directional (measurement-while-drilling, or MWD, or a steering tool) assembly to fluctuate, making it more difficult for the directional driller to follow the planned directional path for the bit. Thus, it may be necessary for the directional driller to back off the bit from the bottom of the borehole to reset or reorient the tool face, which may take a considerable amount of time (e.g., up to an hour). In addition, a downhole motor, such as drilling fluid-driven Moineau-type motors commonly employed in directional drilling operations, in combination with a steerable bottomhole assembly, may completely stall under a sudden torque increase, possibly damaging the motor. That is, the bit may stop rotating, thereby stopping the drilling operation and necessitating that the bit be backed off from the borehole bottom to re-establish drilling fluid flow and motor output. Such interruptions in the drilling of a well can be time consuming and quite costly, especially in the offshore drilling environment.
So-called “wear knots” have been deployed behind cutters on the faces of rotary, earth boring drag bits in an attempt to provide enhanced stability in some formations, notably interbedded soft, medium and hard rock. Drill bits drilling such formations easily become laterally unstable due to the wide and constant variation of resultant forces acting on a bit due to engagement of such formations with the cutters. Wear knots comprise structures in the form of bearing elements projecting from the bit face. Conventionally, wear knots rotationally trail some of the cutters at substantially the same radial locations as the cutters, usually at positions from the nose of the bit extending down the shoulder, to locations that are proximate to the gage. A conventional wear knot may comprise an elongated segment having an arcuate (e.g., half-hemispherical, part-ellipsoidal, etc.) leading end, taken in the direction of bit rotation. A wear knot projects from the bit face a lesser distance than the projection, or exposure, of its associated cutter and typically has a width less than that of a rotationally leading, associated cutter and, consequently, than a groove that has been cut into a formation by that cutter. One notable deviation from such design approach is disclosed in U.S. Pat. No. 5,090,492, wherein so-called “stabilizing projections” rotationally trail certain PDC cutters on the bit face and are sized in relation to their associated cutters to purportedly snugly enter and move along the groove cut by the associated leading cutter in frictional, but purportedly non-cutting, relationship to the side walls of the groove.
The presence of bearing elements in the form of wear knots, while well-intentioned in terms of enhancing rotary drag bit stability, often fall short in practice due to deficiencies in the abilities of bit manufacturers to accurately position and orient the wear knots. Notably, rather than riding completely within a groove cut by an associated, rotationally leading cutter or portions thereof, conventional wear knot designs and placements may contact the uncut rock at the walls of the groove in which they travel, which may excite, rather than reduce, lateral vibration of the bit. Additionally, the areas of the bearing surfaces of the wear knots (i.e., the surface area of a portion of a wear knot that contacts the formation being drilled rotationally behind a cutter at a given DOC) are often difficult to calculate because of the typically half-hemispherical or part-ellipsoidal shapes thereof. Furthermore, the sizes and shapes of wear knots that are formed from hardfacing and that are applied by hand are often not consistent from one wear knot to another. If the bearing surfaces of wear knots on opposite sides of a bit are not almost exactly the same, the bit could be subjected to uneven forces that might result in vibration, uneven wear, or, possibly, cutter or bit failure.
Several patents that have been assigned to Baker Hughes Incorporated address some issues related to DOC, wear knots, and the like. Included among these patents are U.S. Pat. No. 6,200,514; U.S. Pat. No. 6,209,420; U.S. Pat. No. 6,298,930; U.S. Pat. No. 6,659,199; U.S. Pat. No. 6,779,613; and U.S. Pat. No. 6,935,441, the disclosures of each of which are hereby incorporated herein, in their entireties, by this reference.
While some of the foregoing patents recognize the desirability to limit cutter penetration, or DOC, or otherwise limit forces applied to a borehole surface, the disclosed approaches do not provide a method or apparatus for controlling DOC in a manner that is easily and inexpensively adaptable across various product lines and applications.